At various stages during the lifetime of a well, the wellbore will require that a particular operation requiring treatment by fluids, such as for example fracturing, cleaning or stimulation be performed. In performing a wellbore treatment or operation it is often desirable to deliver a fluid treatment to a particular wellbore region rather than to the entire wellbore. To this end, it is well known to use a downhole tool fit with one or more packers to selectively and sealingly engage a wellbore or a casing and isolate the region of the wellbore that is to be treated. The downhole tool is conveyed into and out of the well on a work string, such as coiled tubing.
A number of different types of packers are known (bridge plugs, friction cups, inflatable packers, and straddle packers) and they can be used to isolate a section of the wellbore below the packer or between a pair of packers, depending on the treatment operation to be performed.
Packers, by design, are a barrier to fluid movement, and yet the downhole tools bearing packers are intended to be moved up and down along the wellbore during run-in and when being pulled out of hole (POOH), and are alternately set and released, all of which occurs in a fluid environment. Thus, without fluid management about the packers or through the downhole tool, the operator can end up swabbing the well with possible detrimental effect to the wellbore or the downhole tool.
The downhole tools bearing packers are exposed to varying conditions during use, and debris accumulation around the tool assembly is also concern. Fluid flow during operations or movement can carry significant amounts of debris that settles over and about the sealing device, or within other portions of the tool assembly. This may result in tool damage, or in the tool assembly becoming lodged within the wellbore.
Further, once a particular treatment operation has been performed, it may be desirable to release the downhole tool and associated packers and move it to another location in the wellbore and set the tool again, or to remove it entirely from the wellbore. Generally, a pressure differential across the packer element will exist after an operation in the wellbore is performed, for example a fracturing operation. Unless dissipated or otherwise released, a fluid head uphole of the downhole tool imposes significant fluid forces on the tool and can maintain the packer in an energized state or hold other aspects of the downhole tool in a set condition, risking damage to the tool, the packers or the wellbore if forcibly moved, or preventing any movement at all.
In order to release the tool, the pressure above and below the packer should be equalized. Once the pressure is equalized, the work string can then be manipulated to unset the packer. Accordingly, equalization across a packer after a treatment or other operation has been performed is desirable to avoid debris-related tool malfunction, jamming or immobility of the tool assembly, and potential loss of the well if the tool assembly cannot be retrieved.
US 2011/0198082 teaches a tool assembly including a multi-function valve deployed on work string. Forward and reverse circulation pathways to an isolated interval of a wellbore allow clearing of debris from the wellbore annulus while the sealing device remains set against the well bore. The valve plug is actuable upon application of force to the work string.
US 2012/0055671 teaches a tool assembly deployed on work string. The tool assembly includes an equalization valve that can be opened or closed to control fluid passage between the coiled tubing and treatment zone to the wellbore below. The valve plug may be actuated from surface by pulling or pushing on the tubing to open or to seal the passageway upon application of mechanical pressure to the work string.
US2013/0133891 teaches an equalization valve having a valve plug movable from an open position to a seated position. The valve has a primary fluid passageway and the valve plug defines a conduit that provides for a minimal fluid flow across a sealing element, when the valve plug is at the seated position. The movement of the valve plug between the open position and the seated position is mediated by application of mechanical force applied to the work string.
U.S. Pat. No. 6,474,419 teaches a packer with an equalizing valve for automatically equalizing the pressure above and below the packer element. The packer comprises an equalization valve that has an open position and a closed position. The equalization valve seals to a closed position to prevent flow through the valve when the packer element is actuated to engage the wellbore. Communication above and below the packer is equalized by setting the valve to an open position, after which the packer can be unset and retrieved from the wellbore.
CA 2,683,432 teaches a pressure equalization valve for a work string comprising an equalization valve that closes when a fluid flow having a rate greater than a threshold actuates a shuttle to close the valve. A fluid flow rate less than the threshold maintains the shuttle biased in the open position to open the valve.
U.S. Pat. No. 6,666,273 teaches a plunger-type valve for use in a wellbore. The valve is arranged to be actuated by the differential pressure to selectively allow fluid flow to enter and exit the valve in both directions. The valve seat is biased for controlled flow in one direction and the plunger 704 is biased to enable controlled flow in a second direction. Subsequently, the plunger-type valve can be deactivated to selectively allow fluid flow in only one direction.
U.S. Pat. No. 8,141,642 teaches a valve assembly that is configured to selectively control fluid flow into a fill-up and circulation tool and out of the tool. The valve assembly comprises a movable valve head and a movable valve seat. The valve seat is biased for controlled flow in one direction and the valve stem or head is biased to enable controlled flow in a second direction.
What is needed in the art is an equalization valve that can be moved up and down the wellbore and used in varying positions along the wellbore, without having to pull the valve up to the surface to reset it.
In equalization valves that are opened by bleeding pressure off the valve to equalize pressure above and below the valve, it can be difficult to ascertain from the surface whether the valve is in fact open and able to be moved without damaging the packers. Bleeding off is a particular problem in low pressure wells. In some cases the pressure reduction can allow fluid to flow back into the well, which can carry debris that damages the packers when they are moved. Thus, it would be beneficial to avoid using bleeding off as the primary means by which the valve is opened.
It may at times be necessary to flow fluid through the equalization valve in order to clean components of the work string that lie below the valve. Accordingly, valves actuated by fluid flow are at risk of premature actuation. Similarly, flow-induced closure of a valve can also arise when there is a relative movement of fluid through the valve while moving the tool along a fluid-filled wellbore, thus limiting tripping rates between zones.